Determining organic carbon downhole from nuclear spectroscopy

ABSTRACT

Elemental analysis of an earth formation is obtained using measurements from a gamma ray logging tool. From the elemental analysis, an estimate of the Calcium, Magnesium and Carbon content of the formation is determined. The amount of organic carbon in the formation is estimated from the total Carbon content and the inorganic carbon associated with minerals in the formation. An indication of source rock may be obtained from the Th/U ratio.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application claims priority from U.S. Provisional PatentApplication Ser. No. 60/817497 filed on Jun. 29, 2006. This applicationis also related to an application entitled “Use of Thorium-Uranium Ratioas an Indicator of Hydrocarbon Source Rock” having the same inventorsand being filed concurrently with the present application under Ser. No.11/769,129.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

The present disclosure is in the field of gamma ray testing ofgeological formations. In particular, the disclosure determines theorganic carbon content of a formation from recorded spectra.

2. Description of the Related Art

Well logging systems have been utilized in hydrocarbon exploration formany years. Such systems provide data for use by geologists andpetroleum engineers in making many determinations pertinent tohydrocarbon exploration and production. In particular, these systemsprovide data for subsurface structural mapping, defining the lithologyof subsurface formations, identifying hydrocarbon-productive zones, andinterpreting reservoir characteristics and contents. Many types of welllogging systems exist which measure different formation parameters suchas conductivity, travel time of acoustic waves within the formation andthe like.

One class of systems seeks to measure incidence of nuclear particles onthe well logging tool from the formation for purposes well known in theart. These systems take various forms, including those measuring naturalgamma rays from the formation. Still other systems measure gamma rays inthe formation caused by bursts of neutrons into the formation by aneutron source carried by the tool and pulsed at a preselected interval.

In these nuclear well logging systems, reliance is made upon thephysical phenomenon that the energies of gamma rays given off by nucleiresulting from natural radioactive decay or induced nuclear radiationare indicative of the presence of certain elements within the formation.In other words, formation elements will react in predictable ways, forexample, when high-energy neutrons on the order of 14.2 MeV collide withthe nuclei of the formation elements. Different elements in theformation may thus be identified from characteristic gamma ray energylevels released as a result of this neutron bombardment. Thus, thenumber of gamma rays at each energy level will be functionally relatedto the quantity of each element present in the formation, such as theelement carbon, which is present in hydrocarbons. The presence of gammarays at a 2.2 MeV energy level may for example, indicate the presence ofhydrogen, whereas predominance of gamma rays having energy levels of4.43 and 6.13 MeV, for example, may indicate the presence of carbon andoxygen respectively.

In these nuclear well logging systems, it is frequently useful to obtaindata regarding the time spectral distributions of the occurrence of thegamma rays. Such data can yield extremely valuable information about theformation, such as identification of lithologies that arepotentially-hydrocarbon producing. Moreover, these desired spectral datamay not only be limited to that of natural gamma rays, for example, butalso may be desired for the gamma ray spectra caused by bombardment ofthe formation with the aforementioned pulsed neutron sources.

Well logging systems for measuring neutron absorption in a formation usea pulsed neutron source providing bursts of very fast, high-energyneutrons. Pulsing the neutron source permits the measurement of themacroscopic thermal neutron absorption capture cross-section Σ of aformation. The capture cross-section of a reservoir rock is indicativeof the porosity, formation water salinity, and the quantity and type ofhydrocarbons contained in the pore spaces.

The measurement of neutron population decay rate is made cyclically. Theneutron source is pulsed for 20-40 microseconds to create a neutronpopulation. Neutrons leaving the pulsed source interact with thesurrounding environment and are slowed down. In a well loggingenvironment, collisions between the neutrons and the surrounding fluidand formation atoms act to slow these neutrons. Such collisions mayimpart sufficient energy to these atoms to leave them in an excitedstate, from which after a short time gamma rays are emitted as the atomreturns to a stable state. Such emitted gamma rays are labeled inelasticgamma rays. As the neutrons are slowed to the thermal state, they may becaptured by atoms in the surrounding matter. Atoms capturing suchneutrons are also caused to be in an excited state, and after a shorttime gamma rays are emitted as the atom returns to a stable state. Gammarays emitted due to this neutron capture reaction are labeled capturegamma rays. In wireline well logging operations, as the neutron sourceis pulsed and the measurements made, the subsurface well logginginstrument is continuously pulled up through the borehole. This makes itpossible to evaluate formation characteristics over a range of depths.

Depending on the material composition of the earth formations proximalto the instrument, the thermal neutrons can be absorbed, or “captured”,at various rates by certain types of atomic nuclei in the earthformations. When one of these atomic nuclei captures a thermal neutron,it emits a gamma ray, which is referred to as a “capture gamma ray”.

Prior art methods exist for determining attributes of a formation fromlogging results. See, for example, U.S. Pat. No. 4,712,424, to Herron,U.S. Pat. No. 4,394,574, to Grau et al., U.S. Pat. No. 4,390,783, toGrau, SPE 7430 of Hertzog, SPE9461 by Westaway et al., and U.S. Pat. No.5,471,057, to Herron.

In the exploration for and production of hydrocarbons, it is essentialto analyze the geological basin involved. In determining the hydrocarbongeneration potential of an area, source rocks (i.e. any rock capable ofproducing hydrocarbons) must be identified, along with volume of therock and the quantities of organic matter contained therein.Identification of the presence of source rock is usually critical indeciding whether to continue drilling a well or to abandon it. U.S. Pat.No. 4,071,755 to Supernaw discloses a method in which the energyspectrum of natural gamma radiation occurring in earth formationspenetrated by a well borehole is observed in energy regionscorresponding to uranium, potassium and thorium. Quantitativeevaluations of the relative abundances of these elements are made bycomparing the observed spectra with standard gamma ray spectra. Therelative abundances of these elements may then be interpreted in termsof the organic carbon content of earth formations by comparison withpredetermined relationships found to exist therebetween. U.S. Pat. No.4,686,364 to Herron et al. discloses a method for determining in situthe carbon content of a source rock comprises determining thecarbon/oxygen elemental ratio of the formation via inelastic gammaspectroscopy, determining the porosity of the formation, obtaining theoxygen contents and densities of the fluid and minerals in saidformation, and determining the carbon content from said carbon/oxygenratio, and said oxygen contents and densities of the fluid and minerals.The present disclosure is directed towards a method of determining theorganic content of a formation using only nuclear instruments.

SUMMARY OF THE DISCLOSURE

One embodiment of the disclosure is a method of estimating an organiccarbon content of an earth formation. Radiation resulting frominteraction of irradiation from a source with nuclei in the earthformation is measured. The measured radiation is analyzed to obtain anelemental composition (including carbon) of the formation. The inorganiccarbon associated with the other elements in known minerals is estimatedand the organic carbon is obtained as the difference between the totalcarbon and the inorganic carbon. The elements identified in theelemental composition may include Ca, Mg, Mn and Fe. The known mineralsmay include calcite, dolomite, siderite, rhodochrosite and clayminerals. NMR, acoustic, porosity and/or resistivity measurements mayfurther be made to estimate the carbon that is present in the porespaces of the earth formation. The difference between the hydrocarbon inthe pore space and the excess hydrocarbon is indicative of organiccarbon in the formation. The organic carbon may include carbon in oil,gas, bitumen, coal and/or biogenic matter. The method may also includecharacterizing the organic carbon as a source rock using a Th/U ratio.The Th/U ratio may be determined by making measurements of natural gammaradiation.

Another embodiment of the disclosure is an apparatus for evaluating anearth formation. A radiation source on a logging tool in a borehole isconfigured to the earth formation. At least one detector on the loggingtool is configured to measure radiation resulting form interaction ofirradiation with nuclei in the earth formation. A processor isconfigured to analyze the measured radiation to obtain an elementalcomposition (including carbon) of the formation. The processor isfurther configured to estimate inorganic carbon associated with theother elements in known minerals, and estimate total organic carbon asthe difference between the total carbon and the inorganic carbon. Theelements identified in the elemental composition may include Ca, Mg, Mnand Fe. The known minerals may include calcite, dolomite, siderite,rhodochrosite and clay minerals. The apparatus may further include NMR,acoustic, porosity and/or resistivity sensors, the output of which mayfurther be further used by the processor to estimate the carbon that ispresent in the pore spaces of the earth formation. The processor maythen be configured to use the difference between the carbon in porespaces and the total organic carbon as an estimate of organic carbon inthe formation. The organic carbon may include carbon in oil, gas,bitumen, coal and/or biogenic matter. The processor may be furtherconfigured to categorize the organic carbon as a source rock using aTh/U ratio. The apparatus may include a natural gamma ray detectorconfigured to make measurements that are used by the processor todetermine the Th/U ratio.

Another embodiment of the disclosure is a computer-readable medium foruse with an apparatus for evaluating an earth formation. The apparatusincludes a radiation source on a logging tool in a borehole whichirradiates the earth formation. At least one detector on the loggingtool measures radiation resulting from interaction of irradiation withnuclei in the earth formation. The medium provides instructions thatenable a processor to analyze the measured radiation to obtain anelemental composition (including carbon) of the formation, estimateinorganic carbon associated with the other elements in known minerals,and estimate organic carbon as the difference between the total carbonand the associated carbon. The medium may be selected from the groupconsisting of (i) a ROM, (ii) an EPROM, (iii) an EEPROM, (iv) a FlashMemory, and (v) an Optical disk.

BRIEF DESCRIPTION OF THE DRAWINGS

The present disclosure is best understood with reference to theaccompanying figures in which like numerals refer to like elements andin which:

FIG. 1 illustrates a nuclear well logging configuration in accordancewith the present disclosure;

FIG. 2 shows an instrument suitable for use with the present disclosure;

FIG. 3 shows the basic timing of the pulsed neutron source and theproduced gamma rays;

FIG. 4 shows capture and inelastic spectra from limestone formation withoil-filled borehole;

FIG. 5 shows a comparison of the results of the method of the presentdisclosure with core measurements; and

FIG. 6 shows a Th/U ratio derived from natural gamma ray measurements.

DETAILED DESCRIPTION OF THE DISCLOSURE

Referring now to the drawings in more detail, and particularly to FIG.1, there is illustrated a nuclear well logging configuration inaccordance with the present disclosure. Well 10 penetrates the earth'ssurface and may or may not be cased depending upon the particular wellbeing investigated. Disposed within well 10 is subsurface well logginginstrument 12. The system diagrammed in FIG. 1 is a microprocessor-basednuclear well logging system using multi-channel scale analysis fordetermining the timing distributions of the detected gamma rays. Welllogging instrument 12 includes long-spaced (LS) detector 14,short-spaced (SS) detector 16 and pulsed neutron source 18. In anexemplary embodiment, LS and SS detectors 14 and 16 are comprised ofbismuth-germanate (BGO) crystals coupled to photomultiplier tubes. Toprotect the detector systems from the high temperatures encountered inboreholes, the detector system may be mounted in a Dewar-type flask.Also, in an exemplary embodiment, source 18 comprises a pulsed neutronsource using a D-T reaction wherein deuterium ions are accelerated intoa tritium target, thereby generating neutrons having an energy ofapproximately 14 MeV. The filament current and accelerator voltage aresupplied to source 18 through power supply 15. Cable 20 suspendsinstrument 12 in well 10 and contains the required conductors forelectrically connecting instrument 12 with the surface apparatus.

The outputs from LS and SS detectors 14 and 16 are coupled to detectorboard 22, which amplifies these outputs and compares them to anadjustable discriminator level for passage to channel generator 26.Channel generator 26 converts the output pulse heights to digitalvalues, which are accumulated into pulse height spectra, in which thepulses are sorted according to their amplitudes into a discrete array ofbins. The bins uniformly divide the entire amplitude range. These pulseheight spectra are accumulated in registers in the spectrum accumulator28, the spectra being sorted according to their type: inelastic,capture, or background. After a pulse height spectrum has beenaccumulated, CPU 30 controls the transfer of the accumulated data to themodem 32, which is coupled to cable 20 for transmission of the data overa communication link to the surface apparatus. To be explained later arefurther functions of CPU 30 in communicating control commands whichdefine certain operational parameters of instrument 12 including thediscriminator levels of detector board 22, and the filament current andaccelerator voltage supplied to source 18 by power supply 15.

The surface apparatus includes master controller 34 coupled to cable 20for recovery of data from instrument 12 and for transmitting commandsignals to instrument 12. There is also associated with the surfaceapparatus depth controller 36 which provides signals to mastercontroller 34 indicating the movement of instrument 12 within well 10.An input terminal may be coupled to master controller or processor 34 toallow the system operator to provide selected input into mastercontroller 34 for the logging operation to be performed by the system.Display unit 40, and storage unit 44 coupled to the master controller 34may be provided. The data may also be sent by a link to a remotelocation. Processing may be done either by the surface processor, at theremote site, or by a downhole processor.

In a well logging operation such as is illustrated by FIG. 1, mastercontroller 34 initially transmits system operation programs and commandsignals to be implemented by CPU 30, such programs and signals beingrelated to the particular well logging operation. Instrument 12 is thencaused to traverse well 10 in a conventional manner, with source 18being pulsed in response to synchronization signals from channelgenerator 26. Typically, source 18 is pulsed at a rate of 10,000bursts/second (10 kHz). This, in turn, causes a burst of high-energyneutrons on the order of 14 MeV to be introduced into the surroundingformation to be investigated. In a manner previously described, thispopulation of high energy neutrons introduced into the formation willcause the generation of gamma rays within the formation which at varioustimes will impinge on LS and SS detectors 14 and 16. As each gamma raythus impinges upon the crystal-photomultiplier tube arrangement of thedetectors, a voltage pulse having an amplitude functionally related tothe energy of the particular gamma ray is delivered to detector board22. It will be recalled that detector board 22 amplifies each pulse andcompares them to an adjustable discriminator level, typically set at avalue corresponding to approximately 100 keV. If such pulse has anamplitude corresponding to an energy of at least approximately 100 keV,the voltage pulse is transformed into a digital signal and passed tochannel generator 26 of MCS section 24.

FIG. 2 illustrates a schematic diagram of an instrument suitable for usewith the present disclosure. The Elemental Neutron Spectrometer (ENS™)is a wireline instrument designed to provide formation mineralogicalinformation, shale identification, and clay typing. The enhancedmineralogical data obtained from the ENS also enables enhanced porositymeasurements. The present disclosure is usable in open hole wirelinelogging. In a typical embodiment, the present disclosure uses theECLIPS™ acquisition system of Baker Hughes Incorporated. Alternatively,the present disclosure can be used, for example, with the FOCUS systemof Baker Hughes, Incorporated. Also, under most conditions, the ENS canbe run in combination with Gamma Ray/Spectralog, Neutron, and Densitynuclear tools. The ENS utilizes an axial pulsed neutron generator of thesame type as that used in the reservoir performance monitor instruments.Thus, there are no special storage or transportation requirements exceptthose of a regulatory nature associated with pulsed neutron generators.The logging speed is dependent upon the environment. A typical loggingspeed is in the range of 15-30 ft/min.

The ENS measurement device of FIG. 2 employs the principle ofneutron-induced gamma ray spectroscopy. ENS component parts areencapsulated within wireline device casing 200. The neutron source ofthe present disclosure is typically a pulsed neutron source. The use ofa pulsed neutron source is advantageous over the use of a chemicalneutron source due to its ability to operate over a broader range offrequencies. Neutron source 209 discharges high-energy bursts ofneutrons into the surrounding formation. The electronic pulsed neutrongenerator is typically operated at a rate of approximately 10,000 Hz, sothat each burst takes place within a 100 microsecond window. Gamma raysproduced via interaction of the discharged neutrons and the formationare detected at the scintillation detector 212 attached to acquisitionand telemetry electronics 215. Power supply 201 enables the ENS device.Electronics 203 enables the neutron source. A neutron shield 220attenuates the neutron flux propagating directly from the source to thedetector.

FIG. 3 illustrates the basic timing of the pulsed neutron source and theproduced gamma rays. Time is displayed along the x-axis in microseconds.The gamma ray counts per second (cps) is displayed along the y-axis. Theneutron burst defines a first-detector-gate interval, referred to as the“burst gate” or inelastic gate. Typically a total spectrum of gamma raysresulting from both inelastic neutron scattering and capture gamma rayscattering are produced during the active duration of the neutronsource, and the timing of the inelastic gate enables obtaining the totalspectrum. In the example of FIG. 3, the number of counts risessignificantly (typically to 120 kcps) during the inelastic gate, whichextends approximately from 10 μsec to 40 μsec. The deactivation of theneutron source causes the inelastic gamma rays to disappear from thecount almost immediately. A “background gate” 302-303 is shown at apoint substantially coincident with deactivation of the neutron source.The background gate of FIG. 3 extends approximately from 40 μsec to 50μsec. The counts obtained during the background gate are attributable tobackground gamma rays, but also to capture gamma rays, which make up asignificant portion of the spectrum during the background gate. Thebackground gate is followed by a “capture gate” 301. The capture gatecontains gamma rays substantially due to captured neutrons of thesurrounding formation.

In an exemplary embodiment of the present disclosure, energized neutronsare injected from a pulsed neutron source 209 into a surroundingformation. The scintillation detector records the spectrum over apredetermined time interval. During the inelastic gate, a total spectrumof gamma rays is obtained from the formation layer. During a capturegate, a capture spectrum of gamma rays is obtained from the formationlayer. A determinable factor of the capture spectrum can be subtractedfrom the obtained total spectrum to derive a spectrum substantiallyrepresentative of an inelastic spectrum only. The elemental contributionto the inelastic spectrum and the capture spectrum can then bedetermined by determining a first constituent spectrum from theinelastic spectrum and a second constituent spectrum from the capturespectrum. An operator versed in the arts can then use the determinedelemental contributions to determine a parameter of the surroundingformation.

The derived gamma ray energy spectra for data analysis comprise both thecapture spectrum and the inelastic spectrum. An inelastic gamma ray isgenerated from the nucleus of the atom from which there is a scatteringof initial highly energetic neutrons. A capture gamma ray is emitted bythe nucleus of an atom through absorption of a neutron after its energyhas diminished. FIG. 4 shows capture and inelastic spectra fromlimestone formation with oil-filled borehole. The three spectra are theinelastic spectrum 401, the capture spectra 402, and the backgroundspectrum 403.

A feature of the present disclosure is the analysis of separateinelastic and capture spectra in terms of their constituent spectra.Prior art discusses methods for removing the effects of a capturespectrum from a total spectrum obtained during a burst gate,consequently obtaining an improved inelastic spectrum. A correctedfraction of the capture spectrum is subtracted from the total spectrumin order to generate a representative inelastic spectrum. The correctedfraction is referred to as the capture subtraction factor. The methodfor calculating this value comprises using a capture gamma ray responsefunction to estimate the capture and inelastic components within arecorded time spectrum. Analysis of the spectra can be performed upholeor downhole using a processor or expert system.

A library of elemental basis functions can be used to enable adecomposition of at least one of capture and inelastic spectra intotheir respective constituent spectra. A partial list of elementsincludes Ca, Cl, Fe, Mg, Si. Currently, constituent spectra representing20 elements are usable in the present disclosure. When the fraction of aparticular element obtained from both the capture and inelastic spectrumare reasonably close, then their average value may be used for theelemental analysis. Large differences between estimates for a particularelement obtained by capture and inelastic spectral decomposition shouldserve as a cautionary flag. As part of the spectral decomposition usingbasis functions, it is standard practice to also estimate uncertaintiesalong with the regression coefficients. These uncertainties can be usedto provide an estimate of the amount of an element from the individualestimates obtained from inelastic and capture spectra. The number ofelements can be increased and is not meant as a limitation of thepresent disclosure. Elemental basis functions could further be producedusing various methods. For example, use of a computer can enablegeneration of an elemental basis function of a previously unlistedelement.

The elements that can be readily measured from the capture gamma rayenergy spectrum comprise Ca, Cl, H, Fe, Mg, Si, and S. The elements thatcan be readily measured from the inelastic gamma ray energy spectrumcomprise C, Ca, Fe, Mg, O, Si, and S. The list is not intended to becomplete and other elements could also be identified. Table 1 summarizesthe appearance of several elements readily identifiable in both captureand inelastic spectra. In some cases, the same element can be found inboth the capture and inelastic spectra. Those elements found in both thecapture and inelastic spectra further aid a log analyst in the finalscientific interpretation of the data.

TABLE 1 Element Capture Spectrum Inelastic Spectrum Carbon C Calcium CaCa Chlorine Cl Hydrogen H Iron Fe Fe Magnesium Mg Mg Oxygen O Silicon SiSi Sulfur S S

Once a gamma ray spectrum is extracted for an individual element, it canbe used as an elemental standard. These standards are determinable, forexample, using a combination of empirical data from known formations inthe Nuclear Instrument Characterization Center, and using computersimulations employing detailed physical modeling techniques. Thecombination of these standards that results in the best fit to themeasured spectra determines the elemental yields.

In the present disclosure, capture and inelastic spectra are used forestimating the Calcium and Magnesium content of earth formations. Somedrilling muds include Ca and/or Mg minerals, so that correction to thegamma ray spectra resulting from Ca and/or Mg in the borehole may bepreferable and a dual detector system may be used. Other drilling mudsdo not include Mg, so that measurements from a single detector aresufficient to establish the Mg in the earth formation.

One method of the present disclosure makes use of the fact that Ca andMg most commonly occur in earth formations in the form of calcite(limestone) or dolomite, both of which are carbonate rocks. The termdolomite is used with reference to rocks in which half the Ca atoms ofcalcite have been replaced by Mg atoms. The amount of C that is presentin calcite and dolomite bears a fixed relation to the amount of Ca andMg in the formation. This is also true of partially dolomitizedlimestone in which less than half of the Ca in the limestone has beenreplaced by Mg. To a lesser extent, Mg and Ca may also occur in someclay minerals. For the purposes of the present disclosure, we define theOrganic Carbon (XSC) as the carbon that is not in the carbonateminerals. The term “carbonate minerals” includes other minerals such assiderite (iron carbonate) and rhondochrosite (manganese carbonate).

The relation between the fraction of XSC and the fractions of C, calciteand dolomite in the earth formation is given byf _(XSC)=f_(C) −af _(calcite) −bf _(dolomite)   (1).The coefficients a and b have values of 0.12 and 0.1303 respectively.The terms af_(calcite)+bf_(dolomite) may be referred to as “associatedcarbon” that is associated in a mineral form with other elements in theearth formation. The method can be extended to include other mineralscontaining Ca or Mg. Most of the other such minerals are clay mineralswhose presence can be quantified, for example, by natural gamma raylogs.

The Organic Carbon as defined here has two main components. The first isthe carbon that is present in the form of hydrocarbons in thepore-spaces. The second is in the form of carbon that is in the form ofa source rock. The hydrocarbons in the pore space can be estimated usingother measurements such as NMR logs, porosity logs, acoustic logs and/orresistivity logs using known methods. For use of NMR, see, for example,U.S. Pat. No. 6,952,764 to Chen et al., having the same assignee as thepresent disclosure and the contents of which are incorporated herein byreference. Porosity may be determined from neutron porosity logs or fromacoustic logs; combining this with resistivity logs can give hydrocarbonsaturation and hence carbon content. Thus, it is possible to further getan estimate of the source rock potential of the formations.

FIG. 5 gives an exemplary log obtained using the method of the presentdisclosure. The points denoted by 453 are estimates of XSC over a depthrange of 2100 ft (640 m) in a well using the method described above. Thedepth interval included in the box 451 includes a source rock and is ina formation called the Barnett shale. The points within the box and at afew other depths are estimates of organic carbon from analysis of coresamples. The Organic Carbon estimates from analysis of gamma ray spectraare consistent with the core measurements. It should be noted that theorganic carbon includes oil, gas, bitumen, coal and other biogenicmatter. It should be noted that any graphite in the formation will alsoshow up in the estimate of organic carbon.

Another embodiment of the disclosure makes use of a natural gamma raylogging tool to further characterize the carbon in the earth formation.As would be known to those versed in the art, natural gamma ray toolmeasures gamma rays emitted by natural decay of radioactive nuclei inthe earth formation. The most common radioactive elements are potassium(K), thorium (Th) and uranium (U). As noted in the U.S. Pat. No.4,585,939 to Arnold et al., characteristic energies for thorium, uraniumand potassium are 2.61 Mev, 1.76 Mev and 1.46 Mev respectively.

It is known in the art that U and Th can be used as indicators ofsedimentary processes. See, for example, Adams and Weaver (AAPG 1958).To summarize, in oxidizing conditions, only uranium can assume a moresoluble form whereas the mobility of thorium is limited to mechanicalmeans. Thus, a high Th/U value indicates uranium leaching in oxidizingconditions, commonly found in terrestrial environments, while a low Th/Uvalue indicates uranium fixation due to reducing conditions which arefound in marine environments.

An important aspect of the present disclosure is the recognition that alow Th/U value is indicative not just of sedimentary processes but alsoof organic source rock. This is discussed with reference to FIG. 6,which shows a plot of the Th/U ratio in a well. The zone indicated by501 is a prolific source rock. This is a deep-water shale and the lowTh/U 503 is striking. The curve 505 is the uranium measurement.

It should be noted that the Th/U ratio alone cannot be used to measurethe actual amount of source rock. It should be used in conjunction withthe excess carbon using the method discussed above. Excess carbon insedimentary strata could be related to coal, to petroleum hydrocarbonsin the pores of a rock or it could be related to the organic mattercomposing a source rock. Thus, in order to determine these occurrences,the Th/U ratio is used to determine when excess carbon is eitherattributed to a source rock versus excess carbon associated withhydrocarbon or coal. The Th/U ratio of 2 or below in the presence ofexcess carbon is indicative of carbon associated with a source rock.Uranium because of its redox properties will become concentrated due toits affinity for organic matter in anoxic reducing conditions, andexceed the concentration of Th adsorbed to clays composing source rocks.A Th/U above 2 is indicative of excess carbon which is associated withpetroleum hydrocarbons and coal because Th/U ratios above two showsoxidizing conditions are prevalent thus uranium becomes soluble andmobile and is readily removed whereas Th which is not redox sensitivewill remain. Th/U ratio by itself cannot be used to determine whether asource rock is present unless there is evidence of excess carboncomputed using the method described above. Another example of this isthe Th/U ratio found in Limestone and Dolomite. The ratio is often foundto be below 2, but is unrelated to excess carbon being present. It isrelated to the fact that these trace elements are very low inconcentration in carbonate lithologies anyway. Thus one can see thatTh/U ratio used by itself could be misrepresentative if source rocks arepresent or not.

The disclosure has been described in terms of measurements made usinglogging tools conveyed on a wireline device in a borehole. The termdownhole assembly is intended to include a bottomhole assembly as wellas a logging string conveyed on a wireline. The method can also be usedusing data obtained by sensors conveyed on a slickline. The method canalso be used on data obtained using measurement-while-drilling sensorsconveyed on a drilling tubular. The processing of the data may be donedownhole using a downhole processor or at the surface with a surfaceprocessor. It is also possible to store at least a part of the datadownhole in a suitable memory device, in a compressed form if necessary.Upon subsequent retrieval of the memory device during tripping of thedrillstring, the data may then be retrieved from the memory device andprocessed uphole.

Implicit in the processing of the data is the use of a computer programon a suitable machine-readable medium that enables the processor toperform the control and processing. The machine-readable medium mayinclude ROMs, EPROMs, EEPROMs, Flash Memories and Optical disks.

While the foregoing disclosure is directed to the specific embodimentsof the disclosure, various modifications will be apparent to thoseskilled in the art. It is intended that all such variations within thescope and spirit of the appended claims be embraced by the foregoingdisclosure.

1. A method of estimating organic carbon in an earth formation, themethod comprising: irradiating the earth formation from within aborehole; estimating a spectrum of radiation resulting from interactionof the irradiation with the earth formation-and analyzing the estimatedspectrum to estimate an elemental composition of the formation includingcarbon and at least one other element; using: (A) an estimated amount oftotal carbon in the elemental composition, and (B) an amount ofinorganic carbon associated with the at least one other element in aknown mineral in the earth formation; to make a first estimate of theamount of organic carbon; making a second estimate of the amount oforganic carbon using the first estimate of the amount of organic carbonand an estimate of carbon present in a pore space of the formation; andrecording the second estimate of the amount of organic carbon on asuitable medium.
 2. The method of claim 1 wherein the at least one otherelement is selected from the group consisting of (i) Calcium, (ii)Magnesium, (iii) Iron, and (iv) Manganese.
 3. The method of claim 1wherein the known mineral is at least one of (i) calcite, (ii) dolomite,(iii) siderite and (iv) rhodochrosite.
 4. The method of claim 1 furthercomprising: using an additional measurement made with a formationevaluation sensor for estimating carbon present in the space of theearth formation.
 5. The method of claim 4 wherein making the additionalmeasurement further comprises using at least one of: (i) a nuclearmagnetic resonance tool, (ii) an acoustic tool, (iii) a neutron porositytool, and (iv) a resistivity tool.
 6. The method of claim 4 furthercomprising using a Th/U ratio to characterize the organic carbon as asource rock.
 7. The method of claim 6 further comprising determining theTh/U ratio by making measurements of natural gamma radiation.
 8. Themethod of claim 1 wherein the organic carbon includes at least one of:(i) oil, (ii) gas, (iii) bitumen, (iv) coal, and (v) biogenic matter. 9.The method of claim 1 wherein irradiating the earth formation furthercomprises using a pulsed neutron source.
 10. The method of claim 1wherein the radiation resulting from the interaction further comprisesgamma rays.
 11. An apparatus configured to estimate organic carbon in anearth formation, the apparatus comprising: a radiation source configuredto irradiate the earth formation from within a borehole; a radiationdetector configured to record radiation resulting from interaction ofthe irradiation with the earth formation; and a processor configured to:estimate a spectrum of the recorded radiation; analyze the estimatedspectrum to estimate an elemental composition of the earth formationincluding carbon and at least one other element; estimate an amount oftotal carbon in the elemental composition; estimate an amount ofinorganic carbon associated with at least one other element in a knownmineral in the earth formation; make a first estimate of the amount oforganic carbon from the estimated amount of total carbon and the amountof associated inorganic carbon; make a second estimate of the amount oforganic carbon using the first estimate of the amount of organic carbonand an estimate of the carbon in a pore space of the formation; andrecord the estimate of the amount of organic carbon on a suitablemedium.
 12. The apparatus of claim 11 wherein the at least one otherelement is selected from the group consisting of (i) Calcium, (ii)Magnesium, (iii) Iron, and (iv) Manganese.
 13. The apparatus of claim 11wherein the known mineral is at least one of (i) calcite, (ii) dolomite,(iii) siderite and (iv) rhodochrosite.
 14. The apparatus of claim 11further comprising a formation evaluation sensor configured to make ameasurement indicative of carbon present in a pore space of the earthformation and wherein the processor is further configured to estimatethe amount of carbon present in the pore space of the earth formationusing the measurement of the formation evaluation sensor.
 15. Theapparatus of claim 14 wherein the formation evaluation sensor comprisesat least one of: (i) a nuclear magnetic resonance tool, (ii) an acoustictool, (iii) a neutron porosity tool, and (iv) a resistivity tool. 16.The apparatus of claim 14 wherein the processor is further configured touse a Th/U ratio to characterize the organic carbon as a source rock.17. The apparatus of claim 16 further comprising a natural gamma raytool configured to make a measurement indicative of the Th/U ratio. 18.The apparatus of claim 11 wherein the organic carbon includes at leastone of: (i) oil, (ii) gas, (iii) bitumen, (iv) coal, and (v) biogenicmatter.
 19. The apparatus of claim 11 further comprising a pulsedneutron source configured to irradiate the formation.
 20. The apparatusof claim 11 further comprising a gamma ray detector configured to recordthe radiation resulting from the interaction.
 21. The apparatus of claim11 wherein the radiation source is configured to be disposed on adownhole assembly conveyed into the borehole on a conveyance deviceselected from: (i) a wireline, and (ii) a drilling tubular.
 22. Acomputer-readable medium accessible to a processor, thecomputer-readable medium having instructions which enable the processorto: estimate a spectrum of recorded radiation resulting from interactionof irradiation from a radiation source within a borehole with an earthformation; analyze the estimated spectrum to estimate an elementalcomposition of the earth formation including carbon and at least oneother element; estimate an amount of total carbon in the elementalcomposition; estimate an amount of inorganic carbon associated with theat least one other element in a known mineral in the earth formation;make a first estimate of the amount of organic carbon from the estimatedamount of total carbon and the amount of associated inorganic carbon;make a second estimate of the amount of organic carbon using the firstestimate of the amount of organic carbon and an estimate of the amountof carbon in a pore space of the formation; and record the secondestimate of the amount of organic carbon on a suitable medium.
 23. Thecomputer-readable medium of claim 22 further comprising at least one of(i) a ROM, (ii) an EPROM, (iii) an EAROM, (iv) a flash memory, and (v)an optical disk.